A year ago in Vienna, as the Organization of the Petroleum Exporting Countries met for its November meeting on whether or not to maintain, cut, or increase oil production for member countries, there was a new face on the sidelines. Alexander Novak, Russia’s Energy Minister. Leading up to the negotiations, and the final announcement of an OPEC cut, Novak had a busy couple months jet-setting to Qatar and China to meet with Saudi oil ministers to clinch the deal to cap oil production and cooperate with OPEC to stabilize the oil markets.

Russia’s participation, in terms of sheer volume, gave the production freeze a larger market impact. Prices rose 10% after the decision was initially announced last November. It was the first time Russia joined OPEC members in a collective action since 2001. Tomorrow, on November 30, Russia is expected to join the 9-month extension of the current agreement. By capping production, OPEC and Russia have more or less achieved its goal of stabilizing oil prices, which have been hovering at a near $60 per barrel level, in both US and European markets.

Last November, Russia and Saudi Arabia – OPEC’s biggest producer – were in a similar predicament Both governments faced massive budget deficits and oil revenue shortages due to historically low oil prices that earlier in 2016 had fluttered below $30 per barrel.

Russia’s incentive in 2016 to agree to a production cut was motivated by increasing oil revenues in the short term, but more importantly, the idea was to boost oil prices before selling off shares in Rosneft, Russia’s largest and state-owned oil company. The Russian government, therefore, had a direct financial interest in boosting oil prices to fetch a higher valuation for Rosneft before putting it up for sale.

This year, the Russian government has a much more concrete goal in mind: keep oil prices high through the elections in March of 2018. Rosneft no longer has an interest in prolonging the production cuts, because now that the sale is complete, the company wants to secure its market position – i.e. keep prices high enough to make a profit, but low enough to continue to box out US shale producers.

In 2018, Saudi and Russian interests may not align. Saudi Arabia is gearing up to list its energy giant Saudi Aramco 2018, and wants to see oil prices continue to climb before the billion, if not trillion dollar, IPO. The higher the oil prices, the higher the company can list its initial shares. Russia doesn’t necessarily want to sabotage the IPO, but would certainly benefit from it fetching the lowest price possible.

While OPEC is happy to leave the exit strategy vague, Russia is not. Russia’s oil companies such as Rosneft and Lukoil seem to be placated by prices above $60 a barrel and don’t necessarily support extending the deal any longer.

Of course, Saudi and Russia are not the only voices at tomorrow’s meeting. The 14 member countries of OPEC all have various needs. Nigeria and Libya, which were exempt from the production cap cut last year due to low production and civil unrest, may be forced to comply this year. In Venezuela, the crisis has significantly cut oil production, and major debts at state-owned PDVSA risk further damaging output and refinery potential.

Saxo Bank’s Chief Economist Steen Jakobsen is bearish on a recovery in oil prices. The Danish banker sees the growing trend in electrification, especially in transport, as a direct threat to the fossil fuel market. Jakobsen shared this prediction, along with other forecasts on global energy shifts, at a presentation for financial professionals and journalists in Moscow.

According to Jakobsen, electrification is the “single biggest industry paradigm shift we have seen in the history of my time,” adding that electrification will not only revolutionize the car industry, but “will change the economic structure as we know it.”

“Based on electrification, and the massive amount of potential in the Middle East which is being kept in check right now because of the Saudi Aramco IPO, I think oil could easily see $25 in WTI and $30 in Brent in the next 12 months, and certainly in the next couple of years,” Jakobsen said.

“The number of electric cars will go from 2% this year to 10% next year, and then 25% the following year,” said Jakobsen, who believes this will spell the end of oil. As seen in the chart below, 56% percent of oil demand comes from transport.

The rationale behind the significant jump will be supported by government tax incentives encouraging citizens to buy electric instead of petrol engines. China has emerged a pioneer in using government incentives to clean up its polluted cities. In fact, China has announced that by 2030, no cars in the country will run on petrol. If production and export-based economies such as Germany don’t follow the lead in electrification, they will have major economic gaps to fill once battery-powered engines take over the traditional combustion model. Companies like Mercedes Benz, Porsche, and Audi will have to adapt to the normal of electric vehicles, and reevaluate their business models.

The current streak in oil prices can be explained by supply and demand: “The inventory of oil stock in the world is going down, pushing prices up.” In the near future, when the Middle East is unable to unlock their hydrocarbon potential, this will offset the current price structure, and likely cause a glut in the market.

“We started the year with oil prices being up 25 to 50%, and now year over year, we are flat. There is no new inflation coming, unless of course we go much higher in oil prices.”

Jakobsen’s bearish outlook on oil prices follows the theme for his other predications in the global economy, from blockchain to technology to credit availability.

“Everything that goes on in the world is deflationary,” Jakobsen explained, saying that innovations such as blockchain and automatic will mean that the economy simply needs “less of everything” – fewer bankers, factory workers, and in the case of energy – less oil. This trend can be seen in the strengthening dollar: as the USD grows stronger (and thus US-held debt becomes more expensive to pay off), as a result emerging markets, commodities, and inflation all go down.

Predictions for next 30 years:

Electrification

Demographics

Peak oil demand?

Health care cost mean revision (max % of GDP)

Regulation – Basel III + IV – credit limitation

Higher policy rates (tax on credit)

Automation and robotics

Blockchain – cheaper, faster, and “less everything”

Monopolistic break-up of IT giants: FB, Google, Amazon, Apple

In creating their economic outlooks, Saxo Bank heavily favors “credit impulse” data points, a good predictor of what the real economy will look like in nine months. The tool measures the change of new credit issued as a percentage of GDP.

The recent drop we are seeing in the global credit impulse is the second largest in the history of this chart (which dates back to 1998). The largest decline was in 2007-2008. When faced with an equity slump in the first quarter of 2016, central banks responded with a massive amount of credit expansion, which came to fruition in the beginning of 2017.

“In my opinion, there is a 66% chance probability of a recession in the early parts of 2018 in the US unless something else happens – in terms of taxes, wars, etc.,” the Saxo Bank economist said. Jakobsen noted that the drying up of capital is happening while most central bankers and politicians believe their economies are getting back on track.

“The US interest rate is going to zero. There is no way the world can live with high US interest rates. It’s not only an issue for the US, but for the whole world, because 50% of all net-debt in the world is financed in dollars”.

“The economic reality is that if you have zero growth – or close to zero growth – you have no productivity, no disposable income – you will ultimately see all these things transmit into the banking sector.”

“In China, the amount of credit is still expanding, but the speed of which this credit is expanding is decreasing,” Jakobsen explained.

“In Russia today you have a credit impulse contraction just as big as we see in China. If you have no lending demand, you have a low velocity of money, and low inflation.” A lack of credit in the banking sector will of course have adverse spillover effects on the economy. Under US sanctions, Russia is currently cut-off from long-term loans from US and European institutions, but has attracted credit from Chinese banks to fill the gap. However, in the long term, if Russia’s banking landscape wants to be competitive, it has to be open to foreign banks and capital.

According to Jakobsen, the biggest risk to Russia right now is the US expanding sanctions to include the Russian derivative and bond markets. “It would hurt more than all the sanctions together, because you are taking away all the credit input.” If such sanctions are passed (which Jakobsen sees as likely, as Trump will want to appear tough against the Russians), the ruble could jump back up to 65 or 70 rubles per USD, and the bond spread up by 200 basis points.

The acquisition of the Indian oil refining company Essar Oil by Rosneft and partners will be the largest ever foreign direct investment in India. The $13 billion dollar deal is also Russia’s largest investment abroad.

The prized asset that Rosneft consortium gets out of the deal is the Vadinar refinery in the western region of Gujarat that can process 400,000 barrels of crude oil per day. Control over the second largest refinery in India will give the world’s largest listed oil producer a solid foothold in the fast-growing Indian market, as well as an outlet to energy-hungry South Asia. Other assets that are part of the deal include 2,700 petrol stations, a deep-water port at Vadinar, and power plant that provides electricity for the Vadinar refinery.

The Vadinar refinery was initially planned to open in 1996, but a variety of delays pushed back the open until 2008. The plant itself is modern and has the capacity to refine heavy and extra heavy crude oils. About 40-50% of finished products will be diesel fuels, 15% gasoline, and another 9-10% petroleum coke, a coal-like and carbon-intensive energy source.

The oil flowing into the plant mostly comes from abroad (The Middle East and Latin America), and only about 15-20% is domestically sourced from India. Under the new deal, Rosneft will supply 200,000 barrels of oil per day, or about half of the raw material, over a 10-year period. Rosneft will supply the refinery with pre-paid oil from Venezuela: in August, the Russian oil company lent Venezuelan state oil company PDVSA $6 billion, and the indebted company will pay it back with oil.

Crippling debt is also what led to Essar Oil to seek a buyer. Last year, the company was struggling to pay interest loans on time. In 2016, Essar Oil paid off $600 million in interest, which was about half of the company’s EBITDA (profit before depreciation, interest, taxes, and amortization). No dividends were paid out in the last fiscal year.

Transaction Details

Rosneft itself acquired 49% of the Indian company, and another 49% was acquired by a consortium which includes oil trader Trafigura Group and United Capital Partners (UCP).

There is an observation that the consortium companies play a purely ceremonial role, and were included to avoid international sanctions or interference by the US. Had Rosneft bought all the shares outright, then Essar Oil would become a subsidiary company and would be sanctioned.

According to a report by The Indian Express, Amsterdam-based Trafigura financed its share of the purchase with a loan from Russian state bank VTB. There is an alleged agreement in which Trafigura will transfer its stake to Rosneft in the future. The Moscow-based United Capital Partners has long been suspected of having special ties with Rosneft management. Head of United Capital Partners Ilya Shcherbovich considered it necessary to public refute these rumors.

The total transition amount was officially stated as $12.9 billion, of which $10.9 billion was for the Vadinar refinery asset itself, and another $2 billion for the remaining assets. Rosneft only paid $3.5 billion in cash, and the consortium paid the same amount. VTB will issue Essar a $3.9 billion loan in order to restructure its debt. In total, $10.9 billion was paid to Essar Oil.

Investment in Essar Oil (billions of USD)

Rosneft

3.5

Trafigura and UCP (via VTB loans)

3.5

VTB loan to Essar Oil

3.9

Total

10.9

Essar Oil shareholders received a total of $7 billion. According to the agreement, these shareholders will have to transfer about half of this sum back to Essar Oil to pay back the company’s outstanding accounts payable, including a $2.5 billion debt for Iranian oil deliveries.

Another $2 billion will be spent on the acquisition of the Essar Oil Vadinar oil terminal, an asset which was not previously owned by the company. The new buyers will receive the asset shares once the debts of the terminal (which are on Essar Oil’s balance sheet) are offset.

According to Indian analysts, the $10.9 valuation estimate was based on a 12.5 multiple of EBITDA. This estimate doesn’t look at the market capitalization of the company because the share value of a highly indebted company would be massively undervalued. Instead, the method gives a value to the enterprise as a whole without taking into account the debt load.

For Rosneft and the consortium of buyers, this means that the total return on invested capital was a ratio of 1:12.5, or 8%, and this is before depreciation and taxes. This estimate is approximately twice as large compared to other similar companies to Essar Oil. For example, India’s biggest oil refining company Reliance was estimated to have an EBITDA multiple of 7 at the time of sale.

Perhaps this is because there is potential to expand the capacity of the expensive equipment? Unlikely, as at the time of sale, the refinery was (and still is) operating at about 100% capacity. According to data from Essar Oil, only $5.3 billion in the capital was spent on construction. So, for the amount that Rosneft and its partners paid, it would have been possible to build two such refineries from scratch?

The price tag is linked to currency volatility. Before Rosneft agreed to buy Essar Oil, it was a condition that the company delist from the Indian stock exchange at the end of 2015. Before that, in June 2015, the company stock was worth about 100 Indian rupees per share. In mid-June 2015, after the announcement of a deal with Rosneft, the stock price jumped to 146 rupees per share. By December 2015, Essar Oil was forced to offer minor shareholders a buyout price of 262.8 rupees per share. The Indian government stipulated that Essar Oil had to offer minority shareholders the same share buyout prices it was planning to sell to Rosneft. The all ubiquitous VTB happened to provide money to Essar to buy out minority shareholders. Therefore, Rosneft paid about 2.6 times more than market value before the acquisition was announced. How much is this in monetary terms?

The market capitalization of Essar Oil (the cost of shares, ie the company’s value minus debts) in June 2015 prior to the announcement of the Rosneft deal was about 140 billion rupees, or about $2.2 billion. And Rosneft paid $7 billion for company shares. That leaves a $4.8 billion gap in transaction price and market capitalization.

Even if Rosneft was willing to overpay for access and control, certainly the company cannot justify such a massive discrepancy in value. Some news outlets reported that Saudi and Iranian oil companies initially showed interest in purchasing Essar Oil. This is doubtful – neither Saudi Aramco nor NIOC have ever made major investments abroad, nor do they have the cash.

Let us not forget that this deal carries significant political weight. It was signed at a meeting between Russian President Putin and Indian Prime Minister Modi at the BRICS summit.

Leading up to the Deal

One would think that before completing an acquisition, it would be worthwhile to carefully study what you are getting into. However, Essar Oil released its latest report for the 2016/2017 year on August 19, 2017, that is, almost the same day that the deal with Rosneft was finally sealed.

Apparently, the Russians were in a hurry and did not want to examine the company’s financial position in detail. It is possible Rosneft conducted its due diligence in conjunction with the audit before the company closed its books, although this would be a highly unusual practice.

Before completing the acquisition, one would think it would be worthwhile to study in detail what exactly you are getting. But, apparently, the Russians were in a hurry and did not want to examine in detail the financial position of the company before finally acquiring it. Perhaps, however, that they conducted due diligence simultaneously with the audit, before the closure of the company’s books – although this would be rather unusual. Another oddity is that the final report was produced according to Indian Accounting Standards, unlike previous years, when reports were done according to International Financial Reporting Standards. This is in no way illegal, but it is rather unusual and suspicious conduct right before a sale.

Essar Oil took made another extremely unorthodox move during this period and switched external auditors from Deloitte to an unknown Indian auditor to certify the financial statements. The last audit carried out by Deloitte was published with “qualification”, which doesn’t fully confirm the reliability of the company’s financial statement.

In the two years between the announcement of the sale and the final acquisition, Essar Oil showed significant improvement in its financial performance. For the 2014-2015 fiscal year, EBITDA totaled $900 million, and the next year it reached $1.1 billion, and in 2016-2017, it was already $1.7 billion. In two years’ time, the company’s profitability doubled, yet there were no significant developments in capacity or utilization.

Ahead of a sale, companies engage in “window dressing”, improving the appearance of a company before putting the enterprise up for sale. An example of such a number trick is an increase of activity in an affiliated company, Essar Energy Overseas Limited, which in 2016 shipped about $2.5 billion worth of products. Deloitte declined to recognize the debts as high-quality. We don’t know for sure if Essar Oil engaged in such methods, but if they did and it slipped under Rosneft’s radar, that’s another issue.

Who Exactly is the Seller?

Essar Oil is part of the Essar Group conglomerate, which is owned by the famous Ruia family in India. Originally from rural western India, the family began their business in construction and built a large business empire over the past few decades. In addition to oil, the family has interests in telecoms, banking, and metals.

In 1999, Essar Steel became the first company in the history of India to default on its international debt. More recently, the telecoms arm of the conglomerate has come under legal scrutiny over charges of fraud and bribery to government members to secure 2G services. The slump in commodities caused significant problems in their metals enterprises, and Essar Group debts reached 1.4 trillion rupees, or about $22 billion. Selling Essar Oil was the only way for the Ruia family to manage this heavy debt burden.

The deal was a relief for both the Ruia family and many of Essar Oil’s creditors. Standard Chartered Bank, according to estimates, was able to recover $2.5 of the $5.5 billion that it provided to Essar Group.

How the Purchase Affects Rosneft’s Balance Sheet

Rosneft officially only bought 49% of the shares, which means that Indian company’s activities will not be added to its balance sheet. This means that Essar Oil’s debt will not be added to Rosneft’s already heavy corporate debt situation.

At the end of the second quarter, Rosneft’s had a lot of cash on hand, $12.4 billion to be exact. This cash flow is pre-payments from the Chinese for oil supplies, in a deal struck several years ago.

Rosneft paid $3.5 billion in cash for its stake in Essar Oil. Given its cash reserves, this is of course more than feasible, but the indicators of net debt (debt minus cash) will increase by the same amount.

What’s next?

India is a very promising market with an ever-growing population and increasing purchasing power among the middle class. India is the third biggest oil buyer worldwide, after the US and China, and produces oil that covers 20% of its total oil demand.

Perhaps Rosneft made the right decision to invest in India and secure a foothold in the market, which will become one of the most significant in the world. At the same time, working in India presents its own set of challenge. Indians are tough business partners, and it is extremely important to understand local conditions and markets, especially in downstream products. The dynamic and sales-oriented approach is much more unique than developing upstream fields abroad.

How does the acquisition of an Indian oil refinery fit into the development Rosneft’s strategy? Is this a purely financial investment aimed at dividends, or should this new acquisition help the Russian company achieve some strategic goals?

Many believe the transaction was not of commercial interest but was a geopolitical move to build strong economic ties with India. In 2016, Rosneft offered India’s state Oil and Natural Gas Corporation will increase its stake in Rosneft’s Vankor project to 26 percent, and a group of Indian companies (Oil India, Bharat Petroresources, and Indian Oil) to increase their stake in the Siberian field Vankor to 49.9% for about $3.1 billion. However, it is rather useless to link these transactions: besides the fact they both contain the word “Indian”, they have nothing in common.

Another motivation for the deal could be Rosneft’s scheme to move 200,000 barrels of Venezuelan oil to India per day. Of course one of the main risks is that everything in Venezuela is hanging by a thread – if the Madura government falls, Rosneft could lose its source of oil for the refinery. Between the purchase of the refinery and the prepayments to Venezuela, Rosneft has spent about $17 billion. That is a very expensive risk.

In any case, it’s hard not to agree that the purchase of Essar Oil was truly a landmark deal. But only time will tell if this acquisition turns out to be profitable.

On Friday, August 25, Hurricane Harvey, one of the worst tropical storms to hit the US in twelve years, touched down on land. By then, it had gathered the strength of a category 4 hurricane on a 5 point scale.

The oil refinery industry was inadequately prepared. According to data from the International Energy Agency (IEA), daily oil production from US companies in the Gulf of Mexico decreased by 21.64%, down from 1.75 million to 1.31 million barrels per day.

The supply decrease hasn’t led to an increase in oil prices, as basic economics would lead us to believe. In its path, Harvey has destroyed crucial infrastructure centers that normally order and buy crude oil from Gulf Coast refineries. As long as bad weather conditions continue, most businesses (and their demand for energy) will stay closed. The millions of resident’s in greater Houston have been advised to stay off the roads, a factor which also cuts the demand for refined oil products such as gasoline. Goldman Sachs estimates that demand for oil will be reduced by 2 million barrels per day.

IEA map showing major offshore oil platforms. The fluorescent lines show the intensity of the hurricane storm. From https://www.eia.gov/special/gulf_of_mexico/

Harvey’s effect on oil prices is less obvious.

First, the storm has caused a larger spread between WTI oil prices (trading at roughly $46 per barrel) and Brent (at about $50 per barrel). On Monday, the spread between the US-based benchmark and the European grew to more than $5 per barrel. Brent prices have not taken a hit from the storm.

The primary reason Harvey isn’t destroying WTI prices is due to the recent diversification of the US oil industry into shale, or tight oil.

The US offshore hydrocarbon fields in the Gulf of Mexico produce only about 17% of the country’s total oil output, whereas 48% of the nation’s crude production came from shale reserves. When Hurricane Katrina hit in 2005, it wasn’t the same story, and energy prices, especially for natural gas and gasoline, soared.

CNN reported that Hurricane Harvey has forced 10 oil refineries along the Gulf Coast to shut down. About half of US petroleum and natural capacity is located along the gulf coast in the states of Texas, Louisiana, Mississippi, Alabama, and Florida.

Oil and gas companies began evacuating platforms and rigs before the storm hit. Personnel were evacuated from 98 production platforms (there are a total of 737 in the Gulf of Mexico, both in US and Mexican waters).

Harvey passed through the second largest refinery (600,000 bpd capacity) in Port Arthur, which is owned by Saudi Arabian Oil. Several other companies, such as Shell, confirmed they have closed down their refineries in areas that are in the hurricane’s path. ExxonMobil has closed their Baytown refinery (560,000 bpd capacity), which supplies fuel and petroleum products to the southern and eastern states.

Some refineries continued to operate, but have reduced output. As a result, on Monday, gasoline prices in the US rose by 5% to $1.76 per gallon (before tax). For comparison, gasoline increased by more than 40% following Hurricane Katrina in 2005.

According to investment bank notes from Bank of America and Goldman Sachs, the closure of refineries will lead to a collapse in demand. Goldman Sachs noted that the closure of refineries will translate into 3 million barrels of oil per day not being refined into gasoline and other petroleum products, or about 16% of US refining capacity.

Novatek, the pioneer of Russian LNG in the Arctic, has started commissioning activities on the first liquefaction unit, and the company announced the train will be put into production by December 2017, when the first carrier is scheduled to be delivered to international markets.

The first train (there are a total of three trains at Yamal LNG) will have a capacity of 5.5 million tons of liquefied natural gas, once in full production. The second train is scheduled to start up in 2018, and the third in 2019. When all three trains are active by 2019, the operation will have a capacity of 16.5 million tons of LNG.

The three-train Yamal LNG plant sources natural gas from the South Tambey field on the Yamal Peninsula in Russia’s West Siberia, and the liquefies the gas, and ships it off by boat.

In the short term by 2025, once Novatek’s projects Yamal LNG (16.5 million tons) and Arctic LNG 2 (16.5 million tons) reach full capacity, the company predicts Russia will be the world’s 5th largest producer of LNG. The Arctic LNG 2 project, located on Russia’s Gydan Peninsula, is slated to be completed by 2023. Through auctions and licencing awards, Novatek has amassed a significant amount of bloc holdings in the Russian arctic, which will enable the company to start and complete several more projects like Yamal and Arctic 2.

In the long term, Novatek has ambitions to topple Qatar as the largest LNG producer worldwide (Novatek has said it plans to be producing 100 million tons of LNG in the near future).

Novatek’s plans are not limited to the Arctic. Just recently the company closed a deal to acquire 51% of Gazprombank’s shares in the Cryogas-Vysotsk project in the Baltic Sea. The project includes the construction of an LNG plant with 660,000 tons of capacity per year, as well as an export terminal in the Vysotsk area on the border of Russia and Finland. This project will help Novatek break into LNG marine fuel market. On July 14, a subsidiary of Novatek Gas and Power joined the Society for Gas as a Marine Fuel (SGMF) and SEA \ LNG, an industry coalition that lobbies for LNG as a marine fuel. According to SGMF, already 45 ports worldwide are set up for LNG refueling.

NOVATEK’s subsidiary company Arctic LNG-1 won an auction for the right to explore and produce hydrocarbons in the subsoil area of the Gydan Peninsula of the coast of the Kara Sea in northern Siberia. The acquisition will help NOVATEK secure its foothold in the Russian LNG market, as the Gydan Peninsula license will boost the resource base for large-scale LNG projects in the Yamal region.

The company bought the rights in an auction for $38 million (2.262 billion rubles) for a 27-year lease.

The Gydan site is located in close proximity to the Utrenno field, which is the resource base of Novatek’s Arctic LNG-2 project. The area is estimated to have a total resource potential of 4.74 billion barrels of oil equivalent. Together, the Gydan and Yamal peninsulas are comparable to LNG production in Qatar, NOVATEK has said.

The Arctic LNG 2 project will nearly match Yamal’s production capacity of 16.5 million tons (21 billion cubic meters) per year once it begins operating in 2022-2023. The plant will draw from a resource base of 1.2 trillion cubic meters of proven gas reserves in addition to 50.5 million tons of liquid hydrocarbons.

The addition of Arctic LNG 2 to the Yamal LNG project will significantly reduce the cost of producing LNG in Russia’s Arctic seas, and a liquefaction hub will be set up in Murmansk. Arctic LNG 2 is planned to cost $10 billion and produce 16.5 million tons (21 billion cubic meters) per year once it is in operation starting in 2022 or 2023.

NOVATEK CEO Leonid Mikhelson has said that Russia will soon occupy a quarter of the global LNG market, since the country’s share in world gas reserves is 22-24%. According to Mikhelson, Russia’s vast reserves give the country and obvious competitive advantage in the emerging LNG market.

By the end of this year, NOVATEK’s Yamal LNG project will be commissioned, and eventually production will reach 16.5 million tons per year.

According to NOVATEK, the company already has a significant raw material base on the Gydan Peninsula, including the Utrennoye, Geophysical and Ladderoyskoye fields, as well as the Trekhbogorny, Niavayakhsky, Zapadno-Solpatinsky, Tanamsky, and Severo-Tanamsky fields.

Tehran has announced that gas production at South Pars, the country’s and world’s largest gas field, has doubled in the last four years, and the launch of five new gas platforms has put Iran in reach of surpassing neighboring Qatar’s gas production capacity level.

Iranian President Hassan Rohani, who is up for re-election next month, delivered the good news in April.

According to a statement by the National Iranian Gas Company (NIGC), with the start-up of the five gas platforms has put Iran’s gas production capacity level on par with neighboring Qatar.

The inauguration of South Pars phases 17 through 21 completes the country’s biggest investment, amounting to around $20 billion over the past ten years.

South Pars, which is the world’s largest gas field, has some 230 billion barrel of oil equivalent recoverable hydrocarbons. Two-thirds of the field is located in Qatar, and the other third in Iran. At present, Qatar produces more than 590 million cubic meters of natural gas per day from the field and has plans to boost production by 2022. Iran is trying to catch up in production. Iranian authorities have said that by 2018, gas production from the South Pars field (3,700 sq. km) will exceed that of Qatar’s in the North Field (6,000 sq. km), which is the geological continuation of South Pars.

In total, Iran’s gas production has reached 540 million cubic meters, up from just 240 million when Rohani was elected in 2013, according to Iran’s Ministry of Energy.

Production was curbed by sanctions against Iran, which made it impossible for foreign companies to invest in infrastructure to bring the product to market. As a result, most of Iranian gas produced is used for domestic consumption.

Most of the gas produced is used for domestic consumption, and exports are focused on delivering natural gas via already-existing pipelines to Oman, Pakistan, Iraq, and Kuwait. Tehran relies on oil, not natural gas, for main export revenues.

Iran has not yet been able to replicate Qatar’s successful LNG model, due to a lack of investment as a result of sanctions, and now, an over-supplied market. Qatar is currently the world’s LNG exporter, and ships natural gas to both Europe and Asia, where the product fetches higher market prices.

Iran has signed memorandums of understanding agreements with Gazprom Neft, Lukoil, Tatneft, and Zarubezhneft to jointly develop and operate oil fields.

Thierry Bros, a senior research fellow of The Oxford Institute for Energy Studies sat down with Neftianka to discuss Russia’s future prospects in the LNG market.

Neftianka: You’ve been an analyst on both Russia and LNG markets for decades. You tell us, is LNG Russia’s top energy priority right now?

Bros: The government wants to be a decent player in the LNG world, and again, if you are the government, you have to address the question if you want to be a major LNG player, and ten years later you are a small player, but nowhere near where you wanted to be. It is difficult and risky for companies, therefore we need to partner one way or another.

Today we are in a world where there is too much LNG, other sources are drastically changing merit order system. The Russian government needs to answer one very simple question, is LNG strategic or not? It will need to adapt model to produce. If it decides that the project isn’t strategic, then the market can do it.

We are seeing a relaxed LNG world. I think companies have to think that its still a capitalist world, so you have to think about what type of strategy you want. If you have depletion of historical fields, then you need to find new fields.

You’ve been in the analyst trenches for quite some time now. What do you think about the current slump in LNG prices? Will Russia be able to influence LNG pricing the same way they were able to play with European gas pricing?

I think the Russian state will never be able to control the LNG price, it will be like Brent for oil. The question is, “Do we have sufficient market power LNG to understand the mechanics?” And right now the answer is no. The way to better understand the mechanics is to do more projects.

In order to better understand the LNG market, this means more Russian players and better reporting to the government. In a world where pipeline gas is going to be connected with LNG, Russia has an interest in understanding, but not necessarily controlling, the mechanics of LNG.

There is a very simple question if you are Russia is pipeline gas at discount to LNG, and if so, how can I price this?

The LNG “success” story that everyone is talking about these days is Yamal, an LNG plant with16.5 mtpa that looks like it can break even at $30/barrel prices, even though the area is remote and the technology advanced.

Novatek succeeded in understanding, thanks to Total [partner in Yamal LNG] that costs and CAPEX can’t go through the roof. They understood making it profitable from day one. We can’t twist the spreadsheet, the only way for this to go ahead is for the Russian government to take control, to provide tax holidays, port infrastructure, etc. Novatek and the Russian government definitely came out with a win/win situation.

Yamal has strong state support, provide LNG on time and on budget, a new thing in the LNG world these days. Russian LNG provided by different actors. Remember no monopoly in LNG world. Not enough to put Russia on the LNG map. Still second class player when it comes to LNG. Policy makers would like LNG to become more relevant in Russia.

Conversely, the Shtokman LNG project was thought to be risky, and was postponed. You cant say on your spread sheet you’ll add it up later, it has to be adapted from day one.

Gazprom’s Sakhalin, Russia’s first LNG project, had problems in term of CAPEX during the building phase, but now it operates perfectly fine.

We’ve seen LNG projects on maps for many years, but so far there are only two in Russia [Sakhalin and Yamal].

And what about Gazprom’s Vladivostok LNG project that has been officially shelved since late 2015?

If you are Gazprom, it makes sense to expanding Sakhalin because its cheaper.

Gazprom has never built an LNG liquefaction plant [their partner on the project, Shell, was the operator up until 2009].

Gazprom is extremely good at pipes and conventional upstream. LNG is challenging for them. I think Vladivostok LNG was on the map back many years ago because it was a hedge to Power of Siberia, but with Power of Siberia going ahead, they don’t need

Vladivostok LNG would in theory involve an undersea pipeline from Sakhalin to Vladivostok. Is it really profitable to use pipelines in an LNG project?

Gazprom is used to doing pipelines. They can do the profitability analysis and decide yes or no.

How do energy companies become more vertically integrated? What’s Gazprom’s future in an LNG world?

These big companies have the challenge to adapt – Exxon has the same problem with oil: Their mantra will be “oil, oil, oil” for how long? Gazprom has an advantage as a gas company, its one step ahead in the energy transition. This is why Rosneft is so pushy in breaking into the gas market. Gazprom understands there is a huge risk of unbundling, and for it to try and avoid it, in needs to be profitable day in and day out.

If you are Gazprom, you have to make your case stronger, and that means delivering what the state is expecting.

Gazprom will have a duty to do LNG projects in Russia. If your shareholders ask you do to something that isn’t profitable, you can come back and negotiate.

Of course it is easier to do in Europe, because Gazprom has a long history there, and Asians are tough bargainers. And when we compare this move to what’s going on in Europe, we see it’s a good for Gazprom. They are going to have a tendency to move towards Asia due to financing, sanctions, etc.

Will the Russian government support future LNG projects? How does this change with the 2013 law to “liberalize” the market, letting in new players Novatek and Rosneft to export abroad?

My understanding is that the Russia is creating competition between two national companies, Rosneft and Gazprom, and now Novatek.

It could be a good start. If you want liberalization of markets, this may be a good tool to use later on to move away from regulatory price. If you want to have a price of Russia that is reflective of the market.

Interestingly enough, the Russian government has opened the market to all the companies, and since this law, only one project. Did I pass a law for only one project, or am I going to tell the other companies that its time to deliver?

OK, last question. Do you think that St. Petersburg has the potential to be an LNG pricing hub?

Right now it is for a few players, but you have to start somewhere. You can use a hub as a pricing tool.

Spencer Dale, Chief Economist at BP was in Moscow in mid-February to deliver BP’s most recent Energy Outlook. The report forecasts the upcoming trends in the oil and gas industry in the coming decades. Dale’s presentation focused on global growth, the trend towards decarbonization, and the increasing demand for electricity.

Dale spoke at the Institute of World Economy and International Relations in Moscow, part of his global tour to present this year’s report.

“Do we have a crystal ball that somehow means that can we forecast perfectly for 20 years ahead? Of course not. We now know that any forecast will inevitably be wrong. But I don’t think we should think about forecasting as being right or wrong. The value of forecasting is to better understand the nature of the uncertainty we face.”

The energy demand forecasts are based on the assumption that GDP will grow by 3.4% on average over this period. While some of the growth is driven by an increase in population, a majority will come from productivity growth, led by China and India. More than 2 billion people will shift from “lower income” to middle class, creating more demand for energy.

“The world continues to electrify, with the share of energy used for power continuing to increase,” the economist said.

By 2035, the global demand for energy will increase by 30%, with virtually all growth coming from developing economies.

While oil demand will continue to rise, the real winner will be natural gas with the expansion of LNG, the report says. Coal is expected to see its peak in the mid-2020s. Overall, the three fossil fuels will only make up 77% of the energy mix in 2035, compared to the current 86%.

According to the forecast, in the decades to come, Russia will continue to be the world’s biggest exporter, and in particular, has the potential to increase gas production by 28%.

BP, which recently launched a market campaign to rebrand itself as Beyond Petroleum, is very much oriented towards the role non-carbon sources of energy will play in the future.

“Non-fossil fuels provide almost half of the increase in primary energy in the next 20 years,” Dale said.

Russia’s largest oil company Rosneft and oil pipeline monopoly Transneft have reached a compromise on the transport of oil and oil products for 2017. Rosneft had held out on signing a contract for 2017, which would have left Rosneft without a means to ship their product and Transneft with billion of lost revenue from transport fees.

The dispute between the two power players is longstanding, and stems from the disagreement over compensation payments.

Novatek CEO Nikolai Tokarev and Rosneft head Igor Sechin are both long-time Putin allies, having worked under the President in the 1990s for the city of Saint Petersburg. The two bosses recently met with Russian Energy Minister Alexander Novak and presented the final resolution.

Under the agreement, Rosneft will transport 180,346 million tons of oil via Transneft pipelines, and will ship oil and petroleum products from its recently acquired company Bashneft. The amount of Rosneft will pay to use Transneft’s infrastructure was defined vaguely as “depending on the tariff, amount of oil, and transportation routes.”

Transneft enjoys a monopoly on the transport of Russian oil, shipping more than 90 percent. Rosneft is Russia’s largest producer of oil, accounting for about 40% of the country’s total output.

In December, the pipeline operator, threatened halt pipeline shipments of Rosneft’s oil if a contract wasn’t signed before the end of the year, but this move was blocked by the courts.

With more than 70,000 of kilometers of pipelines, Transneft is the world’s largest oil pipeline company. The company’s monopolistic position makes it a target of not only Rosneft, but also small independent oil producers vying for access to pipelines.